Distribution system analysis using meter data

ABSTRACT

A monitoring system includes a first sensor positioned at a first location along a phase conductor line and a second sensor position at a second location along the phase conductor line. The first sensor is configured to generate a first set of synchrophasor data. The second sensor is configured to generate a second set of synchrophasor data. The monitoring system includes a processor configured to receive the first and second sets of synchrophasor data. The processor is further configured to determine a primary side voltage of at least one distribution transformer electrically connected to the phase conductor line based on a secondary side voltage of the at least one distribution transformer. The processor is further configured to determine at least one phase conductor line condition based on the first and second sets of synchrophasor data and the primary side voltage.

RELATED APPLICATION

The following commonly-owned U.S. utility patent application is relatedto this application and is incorporated by reference herein: U.S. patentapplication Ser. No. ______ entitled “DETERMINATION OF DISTRIBUTIONTRANSFORMER VOLTAGES BASED ON METERED LOADS” (Attorney Docket No.10022/1403).

BACKGROUND

1. Technical Field

This application relates to electrical system analysis and, inparticular, to electrical distribution system analysis.

2. Related Art

Phasor data may be used to analyze power systems such as transmissionsystems. The phasor data may be synchronized allowing various analysesto be completed for conductor lines in the power system usingsynchronized system data. However, sensors used for obtaining the phasordata may be spaced far apart along conductor lines, which may reduceaccuracy in locating a problem with a conductor line based on the phasordata.

SUMMARY

A monitoring system configured to determine at least one phase conductorcondition in a distribution system may include a first sensor positionedat a location along a phase conductor line. The first sensor may beconfigured to generate a first set of synchrophasor data. The monitoringsystem may include a second sensor positioned at a second location alongthe phase conductor line. The second sensor may be configured togenerate a second set of synchrophasor data. The monitoring system mayinclude a processor configured to receive the first set of synchrophasordata and the second set of synchrophasor data. The processor may befurther configured to determine a primary side voltage of at least onedistribution transformer electrically connected to the phase conductorbased on a secondary side voltage of the at least one distributiontransformer. The processor may be further configured to determine atleast one phase conductor condition based on the first set ofsynchrophasor data, the second set of synchrophasor data, and theprimary side voltage of the at least one distribution transformer.

A method of determining at least one condition of a phase conductor linemay include receiving a first set of synchrophasor data associated withthe phase conductor line. The method may further include receiving asecond set of synchrophasor data associated with the phase conductorline. The method may further include determining a primary side voltageof at least one distribution transformer based on a secondary sidevoltage of the at least one distribution transformer. The method mayfurther include determining the at least one phase conductor linecondition based on the first set of synchrophasor data, the second setof synchrophasor data, and the primary side voltage of the at least onedistribution transformer.

A computer-readable medium may be encoded with computer executableinstructions executable with a processor. The computer-readable mediummay include instructions executable to receive a first set ofsynchrophasor data associated with a phase conductor line andinstructions executable to receive a second set of synchrophasor dataassociated with the phase conductor line. The computer-readable mediummay further include instructions executable to determine a primary sidevoltage of at least one distribution transformer based on a secondaryside voltage of the at least one distribution transformer. Thecomputer-readable medium may further include instructions executable todetermine at least one phase conductor line condition based on the firstset of synchrophasor data, the second set of synchrophasor data, and theprimary side voltage of the at least one distribution transformer.

A method of determining a plurality of sensor points in a distributionsystem to obtain synchronized data may include loading a maprepresentative of a distribution system. The method may further includedetermining a first set of sensor points on the map at a first level ofthe distribution system based on first predetermined criteria. Themethod may further include determining a second set of sensor points onthe map at the first level of the distribution system based on a userinput criteria.

Further objects and advantages of the present invention will be apparentfrom the following description, reference being made to the accompanyingdrawings wherein the preferred embodiments of the present invention areclearly shown.

BRIEF DESCRIPTION OF THE DRAWINGS

The innovation may be better understood with reference to the followingdrawings and description. The components in the figures are notnecessarily to scale, emphasis instead being placed upon illustratingthe principles of the invention. Moreover, in the figures,like-referenced numerals designate corresponding parts throughout thedifferent views.

FIG. 1 is a diagrammatic view of an example of a distribution system;

FIG. 2 is an example of a T-equivalent circuit of a distribution system;

FIG. 3 is an example of a technique for decomposing a T-equivalentcircuit;

FIG. 4 is another example of a technique for decomposing a T-equivalentcircuit;

FIG. 5 is an example of the decomposed T-equivalent circuit of FIG. 2;

FIG. 6 is a diagrammatic view of a portion of a distribution system;

FIG. 7 is a flow diagram of an example operation used to determine aprimary side voltage of a distribution transformer;

FIG. 8 is an example of a system configured to determine state variablevalues in a distribution system;

FIG. 9 is an example of a system configured to determine line conductorfaults;

FIG. 10 is a flow diagram of an example operation to determine phaseconductor line faults in a distribution system; and

FIG. 11 is a flow diagram of an example operation to determine sensorpoints in a distribution system.

DETAILED DESCRIPTION

FIG. 1 depicts a diagrammatic view of an example distribution system100. The distribution system 100 may include a substation 102 thatsupplies power along a phase conductor line 104 to a circuit termination106. Distribution systems, such as the distribution system 100, mayinclude more than one phase conductor, such as in a three-phase utilitydistribution system. The diagrammatic view of FIG. 1 illustrates asingle phase as an example; however, the concepts described may apply toa distribution system implementing a plurality of phases, such as in a2-phase or 3-phase utility distribution system.

The distribution system 100 may include a plurality of feeder circuits108. Each feeder circuit 108 is individually designated as FC₁ throughFC_(P) in FIG. 1. Each feeder circuit 108 may be configured to supplypower to one or more customer circuits. Each feeder circuit 108 may beelectrically connected to a secondary side of a correspondingdistribution transformer 110. Each distribution transformer 110 isindividually designated as DT_(1 through DT) _(P). In one example, eachdistribution transformer 110 may be configured to step down (e.g.,transform the voltage from a higher voltage at the primary side to alower voltage at the secondary side) a voltage supplied from thesubstation 102 and to provide the stepped down voltage to thecorresponding feeder circuit.

Sensors 112 may be placed along the phase conductor line 104 to measurevarious values associated with the phase conductor line 104, such asvoltage and current at a point along the phase conductor line 104. Inone example, sensors 112 may be configured to generate synchrophasordata, which may include voltage phasor measurements and current phasormeasurements that are synchronized with simultaneous measurementsoccurring elsewhere within an associated distribution system. In FIG. 1,the sensors 112 are designated individually as S1 and S2, which may eachmeasure phasor voltages and currents at a point of connection along thephase conductor line 104. The data collected by each sensor S1 and S2may be synchronized for allowing various portions of the system to bemonitored at a single point in time. In FIG. 1, the sensors 112 areshown as being located at ends of the phase conductor line 104. Inalternative examples, the sensors 112 may be placed at any locationalong the phase conductor line 104, and more than two sensors may bepositioned along the phase conductor line 104. The distribution system100 may also include other circuit levels below the feeder circuits 108.

In the configuration shown in FIG. 1, voltages and currents associatedwith each feeder circuit 108 may be measured to determine the voltageand currents of the secondary side transformer of each correspondingdistribution transformers 110. Each of these secondary side transformervoltages may be used to determine a corresponding primary side voltageof each distribution transformer 110. Each primary side voltage may beused along with synchrophasor data obtained from the sensors 112 to makedeterminations about the line conditions of the phase conductor line104.

FIG. 2 shows a diagrammatic view of sensors 200 configured to generatesynchrophasor data that may be positioned along a section 202 of thephase conductor line 104. In one example, the section 202 may be theentire phase conductor line 104 as illustrated in FIG. 1. FIG. 2 showsthe section 202 between the sensors 200 as being modeled as aT-equivalent circuit. The phase conductor line 104 may include one ormore equivalent impedances, which may be represented as {tilde over(Z)}₁ blocks in FIG. 2 and any load impedance being designated as block{tilde over (Z)}_(N). The arrow through the {tilde over (Z)}_(N) blockindicates the manner in which the load impedance may vary over time. Inone example, the load impedance {tilde over (Z)}_(N) may represent oneor more feeder circuits electrically connected to the line section 202.

Similar to the sensors 112, the sensors 200 may be used to measurevoltage and current phasors synchronized in a distribution system. Thesemeasurements allow state variables to either be measured or calculatedfor the T-equivalent model, which may provide relevant Information usedto determine a system response to new inputs. The manner in which asystem reaches a present state has no effect on a future state. For agiven state and admissible input, the future state of the system isuniquely determined. For example, the sensor S1 may measure the voltagephasor {tilde over (V)}₁ and current phasor Ĩ₁ at the point ofconnection of the line section 202. Similarly, the sensor S2 may measurethe voltage phasor {tilde over (V)}₂ and current phasor Ĩ₂ at the pointof connection of the line section 202. These values may be determined sothat they are synchronized and used to calculate other state variablesassociated with the T-equivalent circuit, such as {tilde over (Z)}₁,{tilde over (Z)}_(N), {tilde over (V)}_(N), and Ĩ_(N). Using themeasured phasor voltages and currents, these values may be determinedusing a set of state variables equations set forth below:

{tilde over (Z)} ₁=({tilde over (V)} ₁ −{tilde over (V)} ₂)/(Ĩ ₁ +Ĩ ₂)  EQN. 1

{tilde over (V)} _(N) ={tilde over (V)} ₁ −Ĩ ₁ {tilde over (Z)} ₁={tilde over (V)} ₂ −Ĩ ₂ {tilde over (Z)} ₁   EQN. 2

Ĩ _(N) =Ĩ ₁ −Ĩ ₂   EQN.3

{tilde over (Z)} _(N) ={tilde over (V)} _(N) /Ĩ _(N)   EQN.4

Using the synchrophasor data obtained on measurements by the sensors 200allows the state variables to be determined at any instantaneous momentin time when the measurements of the sensors 200 are synchronized intime, such as through a global positioning system (GPS). Themeasurements of the state variables allow various phase conductor lineconditions along the line section 202 to be determined, such as linetemperature, which may be determined based on power dissipation.Additional measurements along the line section 202 may allow moreresolution in determining power dissipation along the line section 202.In one example, the T-equivalent circuit 204 may be decomposed intosmaller T-sections.

The T-equivalent circuit produces a T-matrix relating the {tilde over(V)}₁, Ĩ₁ values to the {tilde over (V)}₂, Ĩ₂ values as follows:

$\begin{matrix}{\begin{bmatrix}{\overset{\sim}{V}}_{1} \\{\overset{\sim}{I}}_{1}\end{bmatrix} = {\begin{bmatrix}A & B \\C & D\end{bmatrix}\begin{bmatrix}{\overset{\sim}{V}}_{2} \\{\overset{\sim}{I}}_{2}\end{bmatrix}}} & {{EQN}.\mspace{14mu} 5}\end{matrix}$

where the T-matrix is a transfer function providing a relationshipbetween input voltages and currents and output voltages and currents ofa T-equivalent circuit.

In one example, the T-matrix may be decomposed into P differentT-sections. FIG. 3 shows a flow diagram of an example decompositiontechnique 300 of a T-equivalent circuit into P T-sections. In FIG. 3,the eigenvectors may be determined through an eigenvector analysis. Asshown in FIG. 3, the eigenvectors ultimately allow P differentT-sections to be determined. The eigenvector technique of FIG. 3 usestwo properties of matrices: the matrix eigenvectors may be used tocalculate an equivalent matrix that is diagonal in form; and the P^(th)root of a diagonal matrix may be found by calculating the P^(th) root ofeach of the diagonal entries independently. Using this technique, theT-matrix may be decomposed into an arbitrary number of T-sections, whichmay be cascaded back together to yield the original T-matrix.

In another example, the T-matrix of Eqn. 5 may be decomposed intosmaller T-sections for analysis. In one example, the T-matrix may befactored into two square root components 400 as shown in FIG. 4. Thisdecomposition technique allows N factorizations to occur resulting in 2NT-sections.

Applying the decomposition technique of FIG. 3 to the T-equivalentcircuit 204 of FIG. 2 may result in P concatenated T-equivalent circuitssuch as that shown in FIG. 5. Each T-section may include a lineimpedance represented by respective {tilde over (Z)}₁ blocks and arespective load impedance {tilde over (Z)}_(N). In one example, a linesection 202 may include P feeder circuits between each synchrophasor S1and S2, such as the feeder circuits 108 shown in FIG. 1. This allowseach T-section in FIG. 5 to include representation of a distributiontransformer associated with a feeder circuit.

Including representation of a distribution transformer in each T-sectionmay allow the primary side voltage of each distribution transformer torepresent an estimate of the magnitude of each node voltage {tilde over(V)}_(N), 1 through P, associated with each T-section during analysis.Once each node voltage {tilde over (V)}_(N) is established, the voltagedrops between adjacent node voltages {tilde over (V)}_(N), as well asbetween each sensor S1 and S2, and an adjacent node voltage {tilde over(V)}_(N) may be determined based on system measurements. The voltagedrops allow the various line conditions to be determined, such as linetemperatures based on dissipated power in line sections. For example,when {tilde over (Z)}₁ in a T-equivalent circuit of FIG. 2 isdetermined, the impedance per distance may be determined since thelength of the line section 202 is typically known or may be estimated.Thus, each impedance {tilde over (Z)}₁ of the smaller T-sections in FIG.5 may be determined based on the line length either between a sensor S1and S2 and an adjacent distribution transformer or between adjacentdistribution transformers.

In one example, the power dissipated may be determined through therelationship of P=V²/R, where V is the voltage drop between adjacentvoltage nodes {tilde over (V)}_(N) or between a sensor 200 and a voltagenode {tilde over (V)}_(N). R is the real part of the line impedancesbetween voltage values, either from the distribution transformers or thesensors. The dissipated power may be used to determine temperatures ofsegments between sensor points (e.g., sensors and the primary side of adistribution transformer) of the line section 202, which may be used forfault analysis.

In one example, the primary side voltage of a distribution transformer600 may be determined based on a respective secondary side voltage. FIG.6 shows an example of a feeder circuit configuration that may be used todetermine primary side distribution transformer voltages. FIG. 6 shows aphase conductor line 602. A primary winding 604 of the distributiontransformer 600 may be electrically connected to the phase conductorline 602 and have a primary side voltage V_(P). A secondary winding 606of the distribution transformer 600 may be electrically connected to oneor more customers forming loads on the secondary side of the transformer600. In the example of FIG. 6, two customer circuits 608, 610 are shown,but more customer circuits may be connected to the distributiontransformer 602. Each customer circuit 608, 610 is shown as beingconnected to the secondary winding 606 in a split-phase configuration.The split-phase connection allows a customer circuit to be connectedacross the secondary winding 606, with a center tap 612 shown as beinggrounded. The split-phase configuration allows a secondary side voltageV_(S) to be received by the customer circuits 608, 610. In otherexamples, the customer circuits may be connected to the secondarywinding 606 in any other configuration.

Power distributed to each customer circuit 608, 610 may be measured andrecorded with a meter 614, 616, respectively. Each meter 614, 616 mayinclude a processor 618, 620, respectively, and a memory 622, 624,respectively. The meters 614, 616 may use the respective processors andmemories to process the power consumption. Each meter 614, 616 mayinclude an analog-to-digital converter (not shown) allowing the meters614, 616 to process digital power usage data. Each meter 614, 616 mayoperate in substantially the same manner in FIG. 6, thus an exampledescribing customer circuit 608 may apply to customer circuit 610, aswell as to other customer circuits that may be connected to the feedercircuit shown in FIG. 6.

In one example, customer circuit 608 may be consuming power suppliedfrom the phase conductor line 600. In the split-phase configurationshown in FIG. 6, current I₁ may flow through the secondary winding 606through conductor line 611 and current I₂ may flow through conductorline 613. The conductor lines 611, 613 may each include common linelosses R_(s1) and R_(s2), which represent common line losses shared byeach connected customer circuit. At least a portion of each of thecurrents I₁ and I₂ may flow through branches 626, 628, respectively, ofthe customer circuit 608 and are represented by branch currents I_(A1)and I_(B1) in FIG. 6.

Each branch 626, 628 may each include a service drop line loss R_(d1),R_(d2), respectively. The branch currents I_(A1) and I_(B1) each flowthrough the meter 614. The meter 614 may include internal current meters630, 632 to measure branch currents I_(A1) and I_(B1). The meter 614 mayalso include an internal volt meter 634 that may determine meter voltageV_(M1) based on the current differential between branch currents I_(A1)and I_(B1). The customer circuit 608 may also include a load representedas R_(I1) and R_(I2) in FIG. 6.

Similarly, the customer circuit 610 may receive branch currents I_(A2)and I_(B2), which may each be only a portion of currents I₁ and I₂,respectively. Each branch current I_(A2) and I_(B2) may flow through arespective branch 636, 638 having the service drop line losses R_(d1),R_(d2). The branch currents I_(A2) and I_(B2) may be measured by themeter 616, and a meter voltage V_(M2) may be determined for the customercircuit 610. The customer circuit 610 may include a load represented asR_(I3) and R_(I4) in FIG. 6.

In one example, a relationship between the meter voltages V_(M1) andV_(M2) and the secondary voltage V_(S) may be used to determine thesecondary voltage V_(S). The relationship may be represented as:

$\begin{matrix}{{\begin{bmatrix}1 & 0 & 0 & {- {I_{1}\lbrack 1\rbrack}} & 0 & {- {I_{T}\lbrack 1\rbrack}} \\1 & 0 & 0 & 0 & {- {I_{2}\lbrack 1\rbrack}} & {- {I_{T}\lbrack 1\rbrack}} \\0 & 1 & 0 & {- {I_{1}\lbrack 2\rbrack}} & 0 & {- {I_{T}\lbrack 2\rbrack}} \\0 & 1 & 0 & 0 & {- {I_{2}\lbrack 2\rbrack}} & {- {I_{T}\lbrack 2\rbrack}} \\0 & 0 & 1 & {- {I_{1}\lbrack 3\rbrack}} & 0 & {- {I_{T}\lbrack 3\rbrack}} \\0 & 0 & 0 & 1 & {- {I_{2}\lbrack 3\rbrack}} & {- {I_{T}\lbrack 3\rbrack}}\end{bmatrix}\begin{bmatrix}{V_{S}\lbrack 1\rbrack} \\{V_{S}\lbrack 2\rbrack} \\{V_{S}\lbrack 3\rbrack} \\R_{d\; 1} \\R_{d\; 2} \\R_{5}\end{bmatrix}} = \begin{bmatrix}{V_{M\; 1}\lbrack 1\rbrack} \\{V_{M\; 2}\lbrack 1\rbrack} \\{V_{M\; 1}\lbrack 2\rbrack} \\{V_{M\; 2}\lbrack 2\rbrack} \\{V_{M\; 1}\lbrack 3\rbrack} \\{V_{M\; 2}\lbrack 3\rbrack}\end{bmatrix}} & {{EQN}.\mspace{14mu} 6}\end{matrix}$

In Eqn. 6, “[1]” may represent the value of the respective variable at afirst time instant, “[2]” may represent the value of the respectivevariable at a second time instant, and “[3]” may represent the value ofthe respective variable at a third time instant. In Eqn. 6, variousassumptions may be made such as R_(s1)=R_(s2)=R_(s)/2 and R_(d1)=R_(d2).In other examples, additional time instants may be used.

In Eqn. 6, I_(T)=I₁+I₂ and represents the total current flowing throughthe customer circuits. Currents I₁ and I₂ may be found by summing thecurrents in the corresponding branches of each customer circuit. Thisallows current I_(T) to be determined by using the current valuesdetermined by each meter and summing the measured currents together. InEqn. 6, the matrix containing current values may be inverted andmultiplied by the matrix containing the meter voltages V_(M1) and V_(M2)at three selected time instants. This allows the matrix containing thesecondary voltage V_(S) to be determined for the three selected timeinstants. Thus, each determined secondary voltage V_(S)[1], V_(S)[2],and V_(S)[3] may each be used for the respective time instant. Each ofthese values may be used to determine the primary voltage V_(P) at therespective time instant based on the turns ratio of the transformer 602.

The configuration of FIG. 6 depicts an example in which metered loadsassociated with customer circuits on a distribution system may be usedto determine the primary side voltage of a connected transformerdelivering power to the load. In other examples, the metered loads maybe used to determine the primary side voltage of a transformer providingpower to the metered loads with equipment positioned between the meteredloads and the transformer. For example, in the configuration shown inFIG. 6, various equipment such as relays or switches may be connectedbetween the customer circuits 608, 610 and the transformer 600. In otherexamples, other transformers may be positioned between the transformer600 and the customer circuits 608, 610. The metered loads associatedwith the customer circuits 608, 610 may be used in these alternativeexamples to determine a primary side voltage associated with thetransformer 600 connected to the phase conductor line

The primary side voltage of distribution transformers, such as thedistribution transformer 600, may be determined in other manners. In oneexample, a distribution system may include a power-line basedcommunication system. The power-line-based communication system may beconfigured to operate on a distribution system such as the distributionsystem 100 in FIG. 1. The power-line-based communication system mayinclude bridge elements located at each distribution transformer, suchas distribution transformers DT₁ through DT_(P). The bridge elements mayallow the secondary side transformer voltages to be measured andtransmitted along the power-line-based communication system. Eachsecondary side transformer voltage may be used to determine thecorresponding primary side voltage based on the turns ratio.

FIG. 7 shows a flow diagram of an example operation to determine aprimary side voltage of a distribution transformer. A step 700 mayinclude determining measured currents flowing through each branch ofeach customer circuit connected to a secondary side of the distributiontransformer for a plurality of time instants. In one example, the step700 may be performed using meters connected in the manner shown in FIG.6 in regard to the meters 614, 616. This arrangement allows each meterto measure current flowing through a respective branch for a number oftime instants, such as three time instants. These currents may be summedtogether at each time instant for each branch providing the totalcurrent flowing through the corresponding branches.

The operation may also include a step 702 of determining the totalcurrent flowing through each customer circuit for the plurality of timeinstants. In one example, the total current at each of the plurality oftime instants may be found by summing the currents measured by eachmeter at each of the plurality of time instants. In one example, step702 may be performed using meters such as the meters 614, 616 shown inFIG. 6. The operation may also include a step 704 of determining a firstmeter voltage and a second meter voltage at the plurality of timeinstants. In one example, step 704 may be performed in a mannerdescribed in regard to FIG. 6 using the meters 614, 616. The operationmay also include a step 706 of determining a secondary side voltage ofthe distribution transformer at each of the plurality of time instants.In one example, step 706 may be performed in a manner described inregard to FIG. 6, which may use Eqn. 6 to determine the secondary sidevoltages at each of three time instants. The operation may also includea step 708 of determining the primary side voltage of the distributiontransformer. In one example, this may be performed by determining theprimary side voltage using a turns ratio and the secondary side voltageof the distribution transformer.

Determining a primary side transformer voltage, or node voltage {tildeover (V)}_(N), for each associated T-section shown in FIG. 6 allows thenode voltages to be used to determine power losses along sections of aphase conductor as previously described. In one example, the analysis todetermine phase conductor line conditions may be determined usingexample configurations shown in FIGS. 8 and 9. FIG. 8 shows an examplesystem configured to generate state variables using phasor data obtainedfrom a pair of sensors, which may be used to generate synchrophasor datafor a phase conductor line section between the pair of sensors, such asthat shown in FIG. 1. The associated state variables may be used todetermine phase conductor line conditions, such as temperature based onpower dissipation. Primary side voltages, such as those determined basedon meter data may be used for various other applications, such as feedervoltage regulation, distribution transformer detection andclassification, power outage detection and localization, and powerrestoration tracking, for example.

The system of FIG. 8 is shown as receiving voltage and currentmeasurements for a three-phase system having phases A, B, and C. Thevoltages V_(A) through V_(C) and the currents I_(A) through I_(C) may bedetermined through line sensors (not shown). The sensed voltages V_(A)through V_(C) and sensed currents I_(A) through I_(C) may be received bya respective A/D converter 802 through 812. The digitized voltage andcurrent data may be received and stored in a respective digital storagedevice, such as the data ring buffers 814 through 824. The digitizeddata may be used to determine the state variable values for each phaseat a particular time. The digitized data may be received by a computerdevice 826 having a processor 828 and a memory 830. The computer device826 may use the digitized data for each phase to generate statevariables associated with each phase.

The digitized phase data may be transformed to the frequency domain bythe computer device 826 through Fourier transform module 832. Thecomputer device 826 may process the frequency domain data in determiningroot mean square (RMS) information for each phase voltage (V_(RMS)) andcurrent (I_(RMS)), as well as real power (P) and reactive power (Q)through a module 834. The digitized phase data may also be used by thecomputer device 826 in a three-phase frequency tracking module 836 todetermine the line frequency.

The RMS voltages and currents for each phase, real and reactive powerfor each phase, and the line frequency may be used by the computerdevice 826 at module 838 which may include a power factor determination,voltage phasor frequency compensation, and current phasors determinationfor each phase from corresponding voltage phasors, current magnitudes,and power factors for each phase. The module 838 may generate voltagephasors ({tilde over (V)}_(ABC)) and current phasors (Ĩ_(ABC)) for eachphase. The computer device 826 may include a phase correction module840, which receives a GPS signal from a GPS signal source 842 and an ACvoltage system frequency from a system frequency source 843, whichresults in generating synchrophasor data for a line sensor. Thesynchrophasor data for each phase {tilde over (V)}_(synch), Ĩ_(synch)may be used by the computer device 826 in a state variable determinationmodule 845, which also implements synchrophasor data from asynchrophasor data module 844 from another adjacent sensor to determinestate variables for each phase for a section of a line conductor. InFIG. 9, a set of state variables 846 is shown which may represent statevariable values for each of the three phases.

The computer device 826 may be a computer device connected to adistribution system such as in a remote terminal unit (RTU). In oneexample, the computer device 826 may generate the state variables andtransmit the state variables to a centralized location for use byanother computer device. In an alternative example, the computer device826 may transmit the synchrophasor data {tilde over (V)}_(synch) andĨ_(synch) to the centralized location which may also receivesynchrophasor data for an adjacent line sensor, which allows the statevariables to be determined at the centralized location.

Upon determination of the state variables for each phase, the statevariables may be used along with primary voltages of the distributiontransformers for a corresponding phase to determine phase conductor linesection conditions. FIG. 9 shows a system 900 that may be configured todetermine the conditions for a line section of phase A. However, a linesection of any other phase, B or C, may be analyzed in substantially thesame manner.

In one example, the system 900 may include a computer device 902. Thecomputer device 902 may be a single computer device or a number ofcomputer devices. In the example of FIG. 9, the computer device 902includes a processor 904 and a memory 906. The processor 904 and thememory 906 may be used to process the state variable values and customercircuit meter data. In one example, the computer device 902 may belocated at a centralized location to receive state variable data fromdata collection devices such as RTUs located throughout a metereddistribution system. Other devices may be used to capture and determinesystem data, such as voltage and current sensors or any other device ormechanism capable of capturing distribution system related data andcalculating state variable values. In alternative examples, the computerdevice 902 may receive synchrophasor data measurements to determine thestate variable values. The computer device 826 in FIG. 8 may also beused to perform the operations and modules associated with the computerdevice 902.

In FIG. 9, the computer device 902 may receive the state variables andcustomer circuit meter data for distribution transformers connected to aline segment being analyzed by the computer device 902. In one example,the computer device 902 may implement a module 908 to process thecustomer circuit meter data in a manner described in regard to FIG. 6 togenerate primary side voltages associated with respective distributiontransformers positioned at various points along a line section beinganalyzed. In one example, the computer device 902 may query a data querydevice responsible for obtaining meter data associated with customercircuits in a distribution system, such as an RTU, a supervisory controland data acquisition system (SCADA), a meter system, or any other datacapture device or system.

The primary side voltages may be used with the state variables by thecomputer device 902 in module 910 to determine the voltage drops alongphase conductor line segments between sensor points, which may includesensors generating synchrophasor data, as well as, node voltages on theprimaries of the distribution transformer. In one example, the module910 may implement a T-section analysis as previously described. Thecomputer device 902 may perform a power dissipation determination atmodule 912 for each segment. The determined power dissipation for eachsegment may be used by the computer device 902 at module 914 todetermine line segment temperature for each segment and generate anoutput signal indicating any segments having abnormal temperatures,which may indicate a fault along that segment.

In another example, secondary side transformer voltages DT₁ throughDT_(P) may be determined using the bridge elements of a power-line-basedcommunication system. The secondary side voltages may be transmittedthrough the power-line-based communication system to the computer device902 and converted to primary side transformer voltages at the module912. In another example, the secondary side voltages received by thecomputer device 902 may be a combination of secondary side voltages frommeters or bridge elements of a power-line-based communication system.

FIG. 10 shows a flow diagram of an example operation to determine phaseconductor line conditions. A step 1000 may include determiningsynchrophasor data based on output from a first and second sensor. Inone example, step 1000 may be performed using a configuration such asthat shown in FIG. 2 in which sensors S1 and S2 are positioned along aline section 202 and configured to generate data that may be used todetermine synchrophasor data.

The operation may include a step 1002 of determining state variablevalues associated with the line section between the first and secondsensors. In one example, step 1002 may be performed using thesynchrophasor data and Eqns. 1 through 4. The operation may also includea step 1004 of determining a T-equivalent circuit of the line sectionbetween the first and second sensors. In one example, this may beperformed using the state variables determined at step 1002.

The operation may also include a step 1006 of decomposing a T-equivalentcircuit into smaller T-sections. In one example, step 1006 may beperformed in a manner described in regard to FIGS. 3 or 4. The operationmay also include a step 1008 of determining meter data from power metersconnected to a secondary side of distribution transformers, which may beconnected to the line segment between the first and second sensors. Theoperation may also include a step 1010 of determining the primary sidevoltages for each distribution transformer electrically connected to theline segment between the first and second sensors. In one example, step1010 may be performed in a manner described in regard to FIG. 6 usingthe acquired meter data.

The operation of FIG. 10 may also include a step 1012 of determiningpower dissipation in a plurality of line segments between the first andsecond sensors. In one example, step 1012 may be performed using thestate variable values and the primary side voltages of the distributiontransformers between the first and second sensors in a T-equivalentcircuit analysis. As previously described, based on the state variablevalues determined in a T-section analysis, the impedance per distancemay be determined for a line segment between the first and secondsensors. This impedance per distance may be used with the determinedprimary side transformer voltages to determine each line segment betweenadjacent distribution transformers and the first and second sensors.

The operation may include a step 1014 of determining if excessivetemperatures exist along any of the line segments. If excessivetemperatures are detected, step 1016 may be performed to determine thefeeder segment associated with the excessive temperature. If faulttemperatures are not detected, the operation may continuously beperformed to monitor the phase conductor line section between the firstand second sensors. The operation of FIG. 10 may be used to determineother phase conductor line conditions associated with fault conditions,such as phase-to-phase, phase-to-ground, three phase faults (shortcircuits) and open phase faults (circuit open on the down stream side,so that no fault current flows).

A distribution system may include various structural or topologicallevels as voltage power is distributed and as feeders branch intovarious sections. These various levels may all be decomposed intoT-sections, allowing a system to be continuously analyzed in a manner aspreviously described. Sensor points may be determined throughout adistribution system from which to receive data for analyzing a systemimplementing T-section analysis. These sensor points may be locationswithin distribution system levels at which to position sensors formeasuring system values, such as sensors S1 and S2 shown in FIG. 1, aswell as locations selected metering points for system analysis asdiscussed in regard to FIG. 6.

FIG. 11 shows a flow diagram of an example operation to determine sensorpoints throughout a distribution system. A step 1100 may include loadinga topographical map of a distribution system. In one example, the mapmay be loaded onto a computer device, such as the computer device 902 ofFIG. 9. A computer device or devices, such as the computer device 902,may execute the entire operation of FIG. 11. The topographical map maybe a distribution system model including various distribution systemequipment that may be used to obtain system data.

A step 1102 may include determining sensor points at a first level of adistribution system based on a first predetermined criteria and an inputcriteria. The topographical map may be used to determine the locationsof any determined sensor points. In one example, the first level of adistribution system may be a feeder circuit level. The feeder circuitlevel may include a circuit from a substation to an end of a circuit. Inone example, sensor points may be selected in which to position sensorsconfigured to obtain synchronized phasor data for analysis. The firstlevel may also include feeder circuit sections, which may be sections ofa feeder circuit defined by interconnection equipment such as circuitrelays or fuses. The first level may also include feeder segments, whichmay be defined by various factors for analysis, such as selected areaswithin a distribution system that may be desired for more resoluteanalysis in comparison to other areas of a distribution system.

In one example, the first predetermined criteria may represent ageneralized system configuration, which may determine sensor points atvarious predetermined conventional sensor locations. In another example,the first predetermined criteria may be contractual obligations. Acustomer connected to a distribution system may have a contract with apower supplier to receive monetary compensation in an event of a poweroutage. This criterion may be used to more closely monitor customers ofthis nature relative to the other customers, which may require moresensor points than other areas of the distribution system.

In another example, the input criteria may be selected based on theparticular configuration of the distribution system being analyzed, suchas load distribution. Within a system, certain circuits may historicallyexperience load volatility in particular areas within a distributionsystem. The input criteria allow sensor points to be determined based onthe load distribution considerations of a particular distributionsystem.

The operation of FIG. 11 may include a step 1104 of determining ifsensor points are to be positioned at a second level of the distributionsystem. In one example, the decision at step 1104 may be based on thefirst criteria. If sensor points are to be positioned, step 1106 mayinclude determining sensor points on the map at the second level basedon the first predetermined criteria and the user input criteria. In oneexample, the second level of the distribution system may include afeeder branch level. A feeder branch level may be one or more circuitsthat branch from the feeder circuit. In one example, the feeder branchlevel may be circuits stepped down in voltage at a transformer or may bethe same voltage as the feeder circuit. The second level may alsoinclude one or more branch segment levels, which may be segments of thefeeder branch levels determined by load considerations or other systemconsiderations such as a particular circuit configuration.

The operation may further include a step 1108 of determining if sensorpoints are to be positioned at a third level of the distribution system.In one example, the decision at step 1108 may be based on the firstpredetermined criteria and the input criteria. If sensor points are tobe positioned, a step 1110 may include determining sensor points on themap at the third level based on the first criteria. In one example, thethird level of the distribution system may include a lateral level. Alateral level may be one or more circuits that branch from the feedercircuit or from a feeder branch, and thus may branch from a first andsecond level. In one example, the lateral level may be a distributionsystem circuit directly connected to a customer, such as the circuitconfiguration shown in FIG. 6. The third level may also include one ormore lateral segment levels, which may be segments of the feeder branchlevels determined by load considerations or other system considerationssuch as a particular circuit configuration. The sensor points for thethird level may be determined for positioning sensors for obtaining dataused for synchrophasor analysis, or the sensor points may be customermeters, such as that described in regard to FIG. 6. The customer metersdata may be used for system analysis along with sensor data, such as ina manner previously described.

The operation may include a step 1112 of determining if additionalsensor points are to be positioned based on the first predeterminedcriteria and input criteria. If additional sensor points are to bepositioned, a step 1114 may include determining sensor points on the mapat the first, second, and third levels of the distribution system basedon a second predetermined criteria. In one example, the additionalsensor points may be determined to be positioned at least one faultlocation level. A distribution system may include an area moresusceptible to faults for various reasons, such as environment, load,circuit configuration, etc. These reasons may represent the secondpredetermined criteria in determining the position of a fault locationlevel and if additional sensor points are to be used. Additional sensorpoints may also be determined at step 1114 based on predeterminedcriteria such as locations of system capacitor banks or distributedgeneration systems, such as combustion turbines or fuel cells, forexample. The sensor points determined at step 1114 may either be sensorsconfigured to obtain data for synchronized phasor analysis or may bemeter data based upon meter availability.

The operation of FIG. 11 may allow analysis of a distribution system todetermine phase conductor line conditions. In one example, upon sensorpoint determination through the operation of FIG. 11, the sensors mayeither be placed, or used if already in place, to gather data allowing astate variable to be determined at various sections of the phaseconductors in the distribution system using a T-equivalent circuit foranalysis. Data from meters selected as sensor points may also be usedfor the distribution system analysis allowing various phase conductorline conditions to be determined, such as in the manner described inregard to FIG. 9.

Although specific components of innovations were described, methods,systems, and articles of manufacture consistent with the innovation mayinclude additional or different components. For example, processors 828and 902 may be implemented as a microprocessor, microcontroller,application specific integrated circuit (ASIC), discrete logic, or acombination of other type of circuits or logic. Similarly, memories 830and 906 may be DRAM, SRAM, Flash or any other type of memory. Flags,data, databases, tables, entities, and other data structures may beseparately stored and managed, may be incorporated into a single memoryor database, may be distributed, or may be logically and physicallyorganized in many different ways. Programs may be parts of a singleprogram, separate programs, or distributed across several memories andprocessors. Additionally modules 832, 834, 836, 838, 840, 845, 908, 910,912, and 914 may be software or hardware implementations on theassociated processors and memories.

While various embodiments of the innovation have been described, it willbe apparent to those of ordinary skill in the art that many moreembodiments and implementations are possible within the scope of theinnovation. Accordingly, the innovation is not to be restricted exceptin light of the attached claims and their equivalents.

1. A monitoring system configured to determine at least one phaseconductor condition in a distribution system, the monitoring systemcomprising: a first sensor positioned at a first location along a phaseconductor line, wherein the first sensor is configured to generate afirst set of synchrophasor data; a second sensor positioned at a secondlocation along the phase conductor line, wherein the second sensor isconfigured to generate a second set of synchrophasor data; and aprocessor configured to receive the first set of synchrophasor data andthe second set of synchrophasor data and to determine a primary sidevoltage of at least one distribution transformer electrically connectedto the phase conductor based on a secondary side voltage of the at leastone distribution transformer, wherein the processor is furtherconfigured to determine at least one phase conductor condition based onthe first set of synchrophasor data, the second set of synchrophasordata, and the primary side voltage of the at least one distributiontransformer.
 2. The monitoring system of claim 1, wherein the processoris further configured to determine the secondary side voltage of the atleast one distribution transformer based on data generated by aplurality of meters electrically connected to the secondary side of theat least one distribution transformer.
 3. The monitoring system of claim2, wherein the data generated by the plurality of meters is a first setof meter voltages and a first set of meter currents measured by a firstmeter and a second set of meter voltages and a second set of metercurrents measured by a second meter.
 4. The monitoring system of claim2, wherein the at least one distribution transformer comprises a firstdistribution transformer and a second distribution transformer; wherein,the processor is further configured to determine a secondary sidevoltage of the first distribution transformer based on the datagenerated by a plurality of meters electrically connected to thesecondary side of the first distribution transformer; and wherein, theprocessor is further configured to determine a secondary side voltage ofthe second distribution transformer based on the data generated by theplurality of meters electrically connected to the secondary side of thesecond distribution transformer.
 5. The monitoring system of claim 1,wherein the phase conductor line includes a plurality of segments; andwherein the processor is further configured to determine a linecondition for each of the plurality of segments.
 6. The monitoringsystem of claim 5, wherein the processor is configured to determine thepower dissipated in each of the plurality of segments based on the firstset of synchrophasor data, the second set of synchrophasor data, and theprimary side voltage of the at least one distribution transformer. 7.The monitoring system of claim 6, wherein the processor is furtherconfigured to determine the at least one line condition for each of theplurality of segments based on the determined dissipated power in eachof the plurality of segments.
 8. The monitoring system of claim 1,wherein the at least one line condition is line temperaturedistribution.
 9. The monitoring system of claim 1, wherein the processoris further configured to determine the secondary side voltage of the atleast one distribution transformer based on a measurement by a bridgeelement of a communication system electrically connected to thesecondary side voltage of the at least one distribution transformer. 10.A method of determining at least one condition of a phase conductorline, comprising: receiving a first set of synchrophasor data associatedwith the phase conductor line; receiving a second set of synchrophasordata associated with the phase conductor line; determining a primaryside voltage of at least one distribution transformer based on asecondary side voltage of the at least one distribution transformer; anddetermining the at least one phase conductor line condition based on thefirst set of synchrophasor data, the second set of synchrophasor data,and the primary side voltage of the at least one distributiontransformer.
 11. The method of claim 10, further comprising determiningthe secondary side voltage of the at least one distribution transformerbased on meter data from a plurality of meters connected to thesecondary side of the at least one distribution transformer.
 12. Themethod of claim 11, wherein determining the secondary side voltage basedon meter data received from a plurality of meters connected to thesecondary side of the at least one distribution transformer comprisesdetermining the secondary side voltage based on a first set of metervoltage data and a second set of meter current data received from asecond meter.
 13. The method of claim 10, wherein determining the atleast one phase conductor line condition comprises determining at leastone respective phase conductor line condition for a plurality ofsegments of the phase conductor line based on the first set ofsynchrophasor data, the second set of synchrophasor data, and theprimary side voltage of the at least one distribution transformer. 14.The method of claim 10, wherein determining the at least one phaseconductor line condition comprises determining power dissipation in thephase conductor line based on the first set of synchrophasor data, thesecond set of synchrophasor data, and the primary side voltage of the atleast one distribution transformer.
 15. The method of claim 14, whereindetermining the at least one phase conductor line condition comprisesdetermining temperature of the at least one phase conductor line basedon the determined power dissipation.
 16. The method of claim 10, furthercomprising determining the secondary side voltage of the at least onedistribution transformer based on data from a bridge element of acommunication system electrically connected to the secondary side of theat least one distribution transformer.
 17. A computer-readable mediumencoded with computer executable instructions, the computer executableinstructions executable with a processor, the computer-readable mediumcomprising: instructions executable to receive a first set ofsynchrophasor data associated with a phase conductor line; instructionsexecutable to receive a second set of set of synchrophasor dataassociated with the phase conductor line; instructions executable todetermine a primary side voltage of at least one distributiontransformer based on a secondary side voltage of the at least onedistribution transformer; and instructions executable to determine atleast one phase conductor line condition based on the first set ofsynchrophasor data, the second set of synchrophasor data, and theprimary side voltage of the at least one distribution transformer. 18.The computer-readable medium of claim 17, further comprisinginstructions executable to determine the secondary side voltage of theat least one distribution transformer based on meter data from aplurality of meters connected to the secondary side of the at least onedistribution transformer.
 19. The computer-readable medium of claim 18,wherein the instructions executable to determine the secondary sidevoltage of the at least one distribution transformer compriseinstructions executable to determine based on a first set of metervoltage data and a second set of meter current data received from asecond meter.
 20. The computer-readable medium of claim 17, furthercomprising instructions executable to determine the at least one phaseconductor line condition to determine at least one respective phaseconductor line condition for a plurality of segments of the phaseconductor line based on the first set of synchrophasor data, the secondset of synchrophasor data, and the primary side voltage of the at leastone distribution transformer.
 21. The computer-readable medium of claim17, wherein the instructions executable to determine the at least onephase conductor line condition comprise instructions executable todetermine power dissipation in the phase conductor line based on thefirst set of synchrophasor data, the second set of synchrophasor data,and the primary side voltage of the at least one distributiontransformer.
 22. The computer-readable medium of claim 21, wherein theinstructions executable to determine the at least one phase conductorline condition comprise instructions executable to determine thetemperature of the at least one phase conductor line based on thedetermined power dissipation.
 23. The computer-readable medium of claim17, further comprising instructions executable to determine thesecondary side voltage of the at least one distribution transformerbased on data from a bridge element of a communication systemelectrically connected to the secondary side of the at least onedistribution transformer.
 24. A method of determining a plurality ofsensor points in a distribution system to obtain synchronized data, themethod comprising: loading a map representative of a distributionsystem; determining a first set of sensor points on the map at a firstlevel of the distribution system based on a first predeterminedcriteria; and determining a second set of sensor points on the map atthe first level of the distribution system based on a user inputcriteria.
 25. The method of claim 24 further comprising: determining athird set of sensor points on the map at a third level of thedistribution system based on the first predetermined criteria; anddetermining a fourth set of sensor points on the map at the third levelof the distribution system based on the user input criteria.
 26. Themethod of claim 24 further comprising: determining a third set of sensorpoints on the map at a third level of the distribution system based onthe first predetermined criteria; and determining a fourth set of sensorpoints on the map at the third level of the distribution system based onthe user input criteria.
 27. The method of claim 26, further comprisingdetermining a fifth set of sensor points on the map, at least one of thefirst, second, and third levels of the distribution system based on asecond predetermined criteria.
 28. The method of claim 23, wherein thefirst predetermined criteria is contractual obligations or distributionsystem configuration.
 29. The method of claim 23, wherein the inputcriteria is load distribution.
 30. The method of claim 23, wherein thesecond criteria is capacitor bank location in the distribution system.